The Historical Roots of Oil Price Monopoly and Its Exploration in the Arabian Gulf

The value of transactions in the oil and gas industry last year more than doubled from 2004, the most activity since the corporate megamergers of 1998–99. And some of the most active players were the formerly stodgy national oil companies (NOCs). Gazprom's U.S. $13 billion takeover of Sibneft and China Natl. Petroleum Corp.'s $3.9 billion buyout of PetroKazakhstan were two of the largest deals that took place last year, according to consultancy John S. Herold, and China Natl. Offshore Oil Corp.'s unsuccessful $18.5 billion bid for Unocal also made headlines. There was a threefold increase in NOC international merger and acquisition activity last year, according to Herold. Times have changed for state-owned enterprises. Most were founded to ensure national energy independence for their countries and have been major employers as well as major funders of government coffers. Now, it is just as likely to see NOCs competing head to head against the majors for prized acreage or for other companies. Some analysts have begun calling these more aggressive state-owned firms international national oil companies (INOCs). The industry is more internationalized, and state companies have become more adept at using technology. States are also concerned about security of supply. The shift of technology ownership from operators to service companies over the past decade and firmer oil prices—which has lessened the need for external financing of some big projects—also have played a role, according to the Accenture consulting firm. Accenture interviewed the senior leaders of 10 NOCs about their objectives. All were interested in growth opportunities, but each had their own distinct priorities, often reflective of their government's policies. All indicated a desire to investigate deals beyond the typical production-sharing or joint-venture contract that, up to now, has been a mainstay of NOC business partnerships. The consequences for the private international oil companies (IOCs)—and the future global energy market—are huge. This new competition is driving up bid prices and pinching returns for private companies' international projects. And the majors are increasingly looking for oil outside mature provinces in places where state enterprises dominate the landscape. Relationships between NOCs are becoming more strategic and longer term as dealings between IOCs and NOCs are becoming more transactional, the Accenture report concluded. NOCs working together make a formidable bidder for projects. China Natl. Petroleum Corp., Lukoil, Uzbekneftegaz, Petronas, and Korea Natl. Oil Corp., for instance, recently joined forces to develop gas fields in Uzbekistan. Often, an NOC and its host government would prefer to work with another NOC, particularly if the countries have similar geopolitical interests. In a recent speech in Singapore, BP Chief Executive Officer (CEO) John Browne pointed out that eight of the 10 largest oil companies in the world are state-owned. "Those state companies control huge resources, far more in total than all the private-sector companies put together," he said. Since 2003, more than half of all reserves sales have been to state companies, he said. To participate in this new competitive climate, private companies will have to bring value to the table, Browne said—namely, "the ability to access and apply knowledge very rapidly on a global scale." That means technology and the skill to apply it. His contemporary, Jeroen van der Veer, Chief Executive of Royal Dutch Shell, agrees. "National and international companies have complementary strengths, and our relationship will be vital for the future," he said at a recent Houston energy gathering. Several NOC leaders in the Accenture study mentioned that they are envious of IOCs' downstream assets and technology. While NOCs may appear to have an advantage over their private counterparts, they also have the burden of satisfying their government's financial needs. In the future, IOCs and NOCs may pursue mergers with each other, particularly if the size and scope of energy projects become burdensome. IOCs and NOCs certainly should consider pursuing joint ventures outside the host country and looking at ways of developing partnerships across the value chain, Marathon CEO Clarence Cazalot said recently. The bottom line is that IOCs need the resources the NOCs control, and NOCs need the technological expertise of private companies, he said.

The Myth of Sustainable Development: Personal Reflections on Energy, its Relation to Neoclassical Economics, and Stanley Jevons

The changes in oil prices that nave occurred in recent years have been accompanied by development of new sources of oil and natural gas. This paper examines levels of net income in many of these areas and rates of profitability. The areas covered include the United States, Canada, North Sea, the Netherlands, Nigeria, Indonesia, and Australia. Returns in these areas are compared with results of synthetic fuels development. Introduction The role of international companies in the producing end of the oil business has changed producing end of the oil business has changed dramatically during the past ten years. Once the equity owners of a great share of the free world's oil reserves in the Middle East and other major foreign producing countries, the international oil companies producing countries, the international oil companies have all but lost their entire ownership in these reserves. Yet, the profits of several of these companies outside the United States have risen significantly in recent years. How have they managed to do this? The answer lies in the success encountered in discovering oil, and in some cases, gas, at remunerative prices elsewhere. While none of these areas is as important in terms of the volumes of oil produced as the countries where take-overs or partial nationalizations have occurred, there are an array of producing countries where unit profits are good and returns on investment are remunerative. Not only the international companies but other more domestically oriented companies have been attracted to these areas, too. The profit and investment data used in this paper are based on published reports, generally paper are based on published reports, generally annual reports to shareholders and reports to the Securities and Exchange Commission. For this reason, most of the data cover results and experience up through 1978. The increased prices that have occurred in world markets in 1979 have added to net income in several areas and, where possible, these developments are included in the discussion. NORTH AMERICA As a base for comparison of developments overseas, it is useful no start this discussion with a look at the United States and Canada. In Table 1, the net income and investment from exploration and production operations of five leading U.S. oil production operations of five leading U.S. oil companies and their affilitates in Canada is shown. Major company operations include interests in a wide cross-section of producing fields and, therefore, halt any bias in a sample that could arise from a smaller company's interest in an unusually profitable or low return field. The use of companies that are affiliated with one another provides for consistency in accounting principles and procedures. Income from the exploration and production operations has been adjusted for certain companies because reported E and P earnings were before interest and in some cases before overhead and taxes. In the cases of Exxon, Imperial, Gulf Canada, and Shell Canada, a share of interest expense, in the same proportion that E and P income was to total pre proportion that E and P income was to total pre interest income, was deducted from reported income to arrive at a net income figure. For Gulf Oil, the same procedure was applied to interest, taxes, and corporate changes. For Conoco and Hudson's Bay, a similarly prorated share of corporate overhead was deducted. The figures show that the rates of return range from 11 percent no 19 percent in the U.S. and 13 to 19 percent in Canada. In assessing and analyzing these data, it is worth noting that the Canadian companies conduct a much larger exploration program — relative to their size — than the U.S. counterparts. In Table II, I have related exploration expenses to E and P net income. For the Canadian companies, these expenses generally represent a higher ratio to net income than for U.S. companies.

Editor's column Higher than normal oil prices during the past few years have led to a sharp rise in spending on upstream technology and innovation. The investment drivers are the need to extend the life of producing assets, improve operational efficiency, access new resources, and improve safety. Those are the results of a survey of 257 oil and gas executives and professionals who work for international and national oil companies, independents, and the service sector in Asia, Europe, and the United States. Conducted by Lloyd’s Register Energy and Longitude Research, the survey examined the rate of upstream innovation and which technologies were likely to become widely adopted in the near and medium term. Some of the participants in the study included Shell, Maersk Drilling, Woodside Energy, UK Onshore Operations Group, Enertech, GE Oil & Gas, TouGas Oilfield Solutions, Horton Wison Deepwater, and the US National Energy Technology Laboratory. Among the findings are: 73% surveyed believe innovation in the upstream sector is increasing. 68% intend to increase R&D budgets in the next 2 years. In the past 2 years, 46% of breakthroughs have been driven by international oil companies and 31% by pure exploration and production (E&P) companies. Respondents expect an increasing role in technology spending by national oil companies (NOCs). Two-thirds of those polled expect NOCs to increase their spending on R&D significantly. The technologies thought to be most valuable in the short term and likely to become mainstream by 2020 are automation, including remote and subsea operations; enhanced oil recovery advances; integrated real-time operating systems and related software advances; deposit-resistant materials and coatings; injection fluid and additive improvements; and improvements in inflow control devices and valves. High-impact technologies going mainstream in 2020 and shortly thereafter include high-pressure/high-temperature drilling, wellhead, and related technologies; multistage hydraulic fracturing; automated and wireless monitoring; digital wells, systems integration, and related technologies; remote sensing, radiofrequency identification, and related technologies; horizontal electrical submersible pumps; steam-assisted gravity drainage and other heavy-oil extraction techniques; composite risers and related technologies; and gellants and other fracking fluid ingredient improvements. The survey was conducted in April and May of this year, before the recent drop in oil prices, and respondents noted that high oil prices since the mid-2000s have led to hefty increases in R&D and innovation spending. Although price seems to drive innovation spending, technology adoption is affected by industry culture. In the survey, only one quarter of respondents said their companies are “early adopters,” while 56% of respondents described themselves as “fast followers,” adopting technologies that have proved their worth. A major factor in slow adoption is the difficulty of testing technologies in appropriate, real-world conditions. More than one in five said this was the biggest problem ensuring quality-assurance requirements associated with deployment. JPT

The good news is that upstream spending is up, way up. But looking beneath the surface numbers reveals that cost inflation is eroding future production gains. With oil prices roughly double and global demand, boosted by consumption from developing countries, 9% higher since 2000, industry upstream capital spending was bound to increase. And it has—a 70% jump (U.S. $340 billion) from 2000 to 2005, according to a new survey of international oil companies (IOCs), national oil companies (NOCs), and independents. But the rising cost of equipment and services ate heavily into that increase, meaning that real investment grew only 5% during the period, says the Intl. Energy Agency (IEA), the energy association that represents 26 major industrial nations. Looking ahead, the companies surveyed reported that they expect to spend $470 billion from now to 2010 on upstream projects. Demand growth in the first part of this decade has raised questions about whether the industry can supply enough oil and gas to the world if demand continues rising at such a rapid pace. Peak-oil theories abound, companies say the easy oil has been found, and host nations are making foreign investment more challenging. And while many reports and studies counter that doomsday scenarios about declining global oil production are faulty, if cost inflation continues to chew up spending increases, the industry will have a hard time replacing production not to mention raising output. Rising consumption from developing countries and industrialized nations such as in western Europe and the U.S. is putting enormous pressure on the majors and NOCs, perhaps unrealistic pressure regardless of whether peak-oil-production forecasts carry weight. In addition, the cost of talent is spiraling higher as the industry's technical-skills shortage creates bidding wars among companies. That situation is unlikely to change anytime soon, regardless of the oil price. Meanwhile, host countries—taking advantage of IOCs' need to boost production—are raising royalties and taxes and asking for a bigger share of the hydrocarbons rent. Service companies have raised prices, while rig rates are much higher than even a year ago. Those factors dictate that even more upstream investment is needed, warns the IEA. It cited Russia, which supplies a quarter of Europe's gas demand, as a country that is underinvesting in its production future—perhaps not even enough to maintain export levels and not enough to be able to export gas to Asia. Technology has helped Russia build back production levels since output peaked in the late 1980s and fell dramatically in the 1990s. Russia was the reason oil producers were able to handle the surge in demand in the first part of this decade. As technical papers and plenary presentations at the recent SPE Russian Oil and Gas Conference in Moscow emphasized, great gains have been made in improving the recovery factor from the country's massive brownfields. But frontier areas, such as the Arctic offshore and large swaths of Siberia, remain ripe for investment. Reports, such as the IEA's, are meant to sound alarm bells. But, from an industry perspective, it is worth noting that its job of supplying energy to meet the world's growing consumption has gotten harder.

Global economic activity, crude oil price and production, stock market behaviour and the Nigeria-US exchange rate

Summary This paper details the technical problems that the engineer will have to face and the qualifications that will be required of an entry-level service-company engineer in the year 2000. The environment in the year 2000 in which the E&P service-company engineer will have to function is addressed as background to these forecasts. Projections are provided for the likely economic, political, and business climates. By the year 2000, there will be far fewer international service companies, but they will be larger and more capable. The service-company engineers will have to understand better the needs and problems of the international oil companies because they will have to work in partnership with the international companies personnel in mostly hostile environments. The engineers will have to have broader skills and be more systems-oriented. They will have to be proficient in computer and software technology and effective team players with good communication and interpersonal skills. Introduction As a representative of the petroleum E&P service industry, I was asked to look at the role of engineering in the year 2000 by addressing five questions. What aspects of the petroleum (E&P) industry will your segment be primarily concerned with in the year 2000? What will be the significant technical problems addressed by the petroleum industry during the remainder of the century? What support will computers provide the engineer in the year 2000, and how should the engineer be prepared to use this technology effectively? How will the functions of engineers change during the remainder of this century? What qualifications will be required for an entry-level engineering position in the petroleum industry in the year 2000? Before I attempt to address these questions, I believe it is important to look at the likely economic, political, and business climates that will exist in the year 2000. (The Appendix provides a detailed look at these climates.)Worldwide demand for oil and gas will grow at a rate of 1 to 1½%/yr during the next 15 years.The current excess capacity in worldwide crude oil production will disappear by the mid-1990's.The increase in worldwide demand cannot be met by sufficient production increases outside the Middle East.U.S. crude oil needs will be increasingly met by imports. Imports will rise from approximately 25% of U.S. needs today to 43 to 52% by the year 2000.The U.S. must maintain a considerable E&P program to minimize its dependence on imports.In the year 2000, an investment of $22 will be required for 1 bbl [0.16 m3] of reserves added in North America, as opposed to $4.40 for the Middle East.The annual E&P investment in the U.S. during the 1990's will exceed the peak yearly investments of $42 billion to $43 billion in the early 1980's.In a rational market, the price of oil in the year 2000 will be in the range of $40 to $50/bbl [$252 to $314/m3] (1985 dollars).It is likely that Saudi Arabia will limit production, prolong the lives of its reservoirs, and promote a gradual increase in oil prices.The international oil companies should have the money and technology needed to find and to develop the needed reserves. Role of the International E&P Service Companies Exploration and development costs are currently very low as a result of the large overcapacity in the petroleum service industry. Drilling and development costs are very attractive today. Because of the great pressure on the going rate for their products and services, a crunching consolidation is taking place among the E&P service companies. At the end of this consolidation period, far fewer companies will exist. Those remaining will be financially stronger and should be able to meet the requirements of the domestic and international oil companies. At risk, however, is the experience level in the service industry. It is clear that the current downsizing and consolidation are removing many experienced people. It will be impossible to maintain the experience base developed in the service industry during the past 5 to 10 years. It is likely that companies will be forced to relearn a number of things. This learning process will not come cheaply to service companies or their customers.

The paper introduces a new measure that jointly identifies and disentangles the oil supply shocks of crude oil into exogenous and endogenous, by quantifying the positive and negative shocks to oil production caused by events outside the oil market (exogenous) or as a consequence of the normal functioning of the oil market (endogenous). The objective is to examine how the use of alternative measures of oil supply shocks affects our assessment of the dynamic effects of supply shocks on the real price of oil since 1990. Results show that for most of the 1990s, shortfalls in oil production that were brought about by geopolitical episodes accounted for about 7% of the variability in global crude oil production. However, this pattern reverses after 2000 onwards, as fluctuations in global oil production are largely attributed to market-specific events (6%). We show that oil supply shocks may have very different effects on the real price of oil, depending on the underlying specification of the shock. In particular, the measures that capture market-driven shifts in oil supply are found to be more plausible than the rest in explaining the variability of the real price of oil, especially when compared with flow supply shocks. In fact, analysis suggests that flow supply shocks underestimate the historical contribution of oil supply shocks to changes in the real price of oil, in contrast to total supply shocks that appear to have exerted significant upward pressure in the real price of oil especially between 2003 and mid-2008. Overall, endogenous supply shocks play an increasing important role in the historical evolution of the oil price, but it must be noted that oil price developments after 2010 are largely attributed to exogenous supply shocks. We conclude that historically the supply side of the market has been an important determinant of the real price of oil after all.

Many of the Intergovernmental Panel on Climate Change’s Special Report for Emission Scenarios and Representative Concentration Pathways (RCP) projections (especially RCP 8.5 and 6) project CO2 emissions due to oil consumption from now to 2100 to be in the range of 32–57 Gb/yr (87–156 mb/d) or (195–349 EJ/yr). World oil production (crude plus condensate) was almost constant from 2002 to 2011 at about 74 ± 1 million barrels per day (mb/d) (US Energy Institute Agency, US EIA). There was an increase in world oil production after January 2011 that was mostly due to a surge of about 6 mb/d in light tight oil (LTO) production in the USA. This increased global oil production to just above 80 mb/d. Meanwhile, production in the rest of the world remained constant. The surge in the USA resulted in a sustained situation where supply was greater than demand globally, and this initiated a crash in the price of oil. The price of oil decreased from about $100 per barrel in mid-2014 to less than $30 per barrel in early 2016. Once the oil price declined, it was further enhanced and sustained by a decrease in demand due to a slowdown in the global economy. Because LTO is expensive to produce and was unprofitable after the price crash for the exploration and production companies, the surge in US production ended in about April 2015. Now, production of LTO in the USA is declining and global oil production is as well. New oil discoveries have reached a 70-year low, which does not bode well for future production. If the present patterns persist, it is unlikely that world oil production will exceed present US EIA oil production values of about 27–29 Gb/yr (equivalent to 75–80 mb/d) or (171–182 EJ/yr). It is unlikely that the demand for oil production required for CO2 emissions in RCP8.5 and RCP6 will be met.

This chapter identifies the major geostrategic challenges that have emerged during the last two decades and assesses their implications for the global oil and gas sectors. The historical development of oil prices shows that there have been two major periods of volatility, 1973–1986 and 1998–present, each of which was preceded by two relatively stable periods. The two oil price shocks of the 1970s that were triggered by geopolitical events had long-term effects on global politics and economics. Major oil and gas producers faced the challenges of declining consumption on the demand side, as consumers turned to alternative energies, energy efficiency improved, and non-Organization of Petroleum Exporting Countries (OPEC) oil supplies increased. The crisis in the 2000s, on the other hand, had similar but more intense consequences, deeply altering the structure of oil and gas markets. We identify two major challenges facing the oil and gas industry: energy substitution and resource scarcity. While the substitution of coal and renewables threatens to reduce oil and gas demand, resource scarcity is expected to promote the development of unconventional hydrocarbon resources such as shale oil and gas and heavy oil. Unlike in the 1970s, oil consumption did not decline when oil prices peaked in the 2000s. Moreover, the recent fall in oil and gas prices created a fiscal challenge for conventional producers, such as OPEC countries, and non-OPEC countries like Russia and Mexico, whose governmental budgets depend on export revenues. These fiscal challenges are expected to increase competition between national oil companies (NOCs) and international oil companies (IOCs), necessitating structural change in the governance of the industry. The NOCs are expected to continue dominating the industry and due to the increasing intervention of the corresponding governments, the next decades could experience a rise in state capitalism not only in major oil and gas producing countries but also in the global energy business.

“Consuming countries would be well advised to utilize this time of relaxed supplies to adopt policies for a long term stabilization of the global energy market.” Michael G Renner looks at ways of influencing the pricing and marketing of oil in moving toward “a more rational equitable energy future”.

The oil and gas industry is in the midst of a critical transition driven by a series of factors, including the Asian energy-demand crunch of 2004, the 2005 hurricanes in the Gulf of Mexico, and recent low discovery rates. These factors, coupled with political uncertainties, threats to petroleum infrastructure, production disruption resulting from civil unrest, and limited access by international oil companies (IOCs) to giant resources in the Middle East and the former Soviet Union, have ushered in what has been referred to as the "Age of Energy Supply Anxiety." In addition, higher oil prices and mounting political pressures, combined with a bit of anti-Americanism and rapidly growing demand for energy in the Asian market (particularly in China), are stimulating producing countries to increase control of their oil and gas resources and move toward resource nationalism. The resulting global scramble by both IOCs and national oil companies (NOCs) to secure hydrocarbon resources has altered the industry's competitive landscape significantly, which in turn has caused a major shift in the balance of power favoring the NOCs, mandating new perspectives on negotiations and partnerships. No longer are NOCs managing only state-owned hydrocarbon resources to their nation's long-term benefit, they are also expanding internationally to secure the additional energy resources necessary for sustainable economic growth for their countries. In other words, NOCs are becoming international exploration companies, competing with IOCs at home and in the world marketplace. The Effect of a Paradigm Shift Considering that governments and NOCs control more than 80% of the world's remaining oil reserves, are expanding and upgrading refineries and infrastructure, and are developing gas resources, the effect is considerable. But that has not always been the case. In the past, when oil prices were low, investments in exploration dropped, and governments were eager to create incentives to attract investments—including reducing tax rates and state participation, or providing royalty relief. All that changed in 2003 when oil prices began to soar. Many countries—primarily those with immense resources such as Russia, Nigeria, Libya, Angola, and Venezuela—reversed gears and raised taxes and/or increased state participation in hydrocarbon licenses. In Latin America, where the public's perception was that oil and gas companies made excessive profits at their expense, energy policies have become highly regulated. Increases in state-take range from 2% in Angola to 24% in Nigeria and 43% in Argentina. In Algeria—formerly known for being one of the most welcoming countries for foreign energy investors—a new government decree was enacted at the beginning of September 2006. Arguing that this decree safeguards the role of Sonatrach, Algeria's NOC, it specifies that Sonatrach will be given a 51% stake in all upstream development projects as well as midstream pipeline and refinery projects.

This article discusses the relationship between the private international oil company (IOC) Royal Dutch Shell and Russia as an oil producing and oil exporting state during a period when oil prices were moving towards unforeseen heights (2005-2007). By examining this dynamic relationship, this study aims to contribute to an understanding of Russia’s discursive and culturally produced history. The history of a state-oil company interaction has shown that the use of legal instruments is a good indicator to determine the nature of the relationship between oil-producing states and IOCs – a relationship that often has been characterized by periods of cooperation or conflict.At the centre of inquiry is how the oil major understands the law in Russia, and in particular the enforcement of the country’s formal written rules during legal conflicts over the development of the Sakhalin-II oil and gas fields (in which Shell until December 2006 controlled a majority stake). After identifying the violations of formal laws, I conclude that Shell understands that the formal rules of the game are subordinate to the unwritten laws of energy politics and in particular the informal demands of contemporary Russian society. The article also illustrates that oil-producing states have the upper hand in conflicts over the development of oil and gas resources.

The World Bank-introduced ‘Zero Routine Flaring by 2030’ (ZRF) Initiative is well on its way to establishing a new global industry standard; one that is very important if governments and industry are to make significant strides to help mitigate climate change. Launched in 2015 by the UN Secretary-General and World Bank President, ZRF commits governments and oil companies to (a) not routinely flare associated gas in new oil field developments, and (b) to end routine flaring at existing (legacy) fields by 2030. (Routine flaring is defined as flaring during normal oil production operations in the absence of sufficient facilities or amenable geology to re-inject the produced gas, utilise it on-site, or dispatch it to a market. The ZRF Initiative clearly states that venting is also not an acceptable substitute for flaring.) A review of the governments and companies that have already endorsed ZRF reveals that many of the major producers recognise the value of making a public commitment and working to end a 150-year-old industry practice. There are now over 70 endorsers, but more governments and companies must join the global effort if there is to be real progress and establishment of a de facto industry standard. Those that have endorsed the ZRF Initiative say it has other tangible benefits. For example, the many international oil companies that already have a no-flaring policy for new oil field developments consider the Initiative a positive contribution because it will level the playing field – other companies would adopt the same good practice and governments would require it. So, the Initiative also reduces regulatory uncertainty and risk. To achieve ZRF on a global scale, collaborative action such as through the Global Gas Flaring Reduction Partnership (GGFR) – a public-private initiative comprising international and national oil companies, national and regional governments, and international institutions – will be required. GGFR is focused on increasing the use of natural gas associated with oil production by helping remove technical and regulatory barriers to flaring reduction, conducting research, disseminating best practices, and developing country-specific gas flaring reduction programs. GGFR is also focused on helping develop financing tools for flare-out projects, such as a new program with the Global Infrastructure Facility (GIF) to fund feasibility studies of solutions to monetize flared or vented gas from onshore and offshore oil production facilities.

Determining the optimum well locations while developing a field contributes significantly to efficient reservoir management. Most optimization problems have focused on maximizing the Net Present Value (NPV) of the project. However, the ultimate aim of projects differs between international and national oil companies. The primary aim of international oil companies (IOCs) is to maximize its profit (NPV). As far as a national oil company is concerned, apart from maximizing NPV one of its main objective is to sustain its resources for as long as possible by delaying abandonment i.e., national oil companies (NOCs) aim to increase the field recovery factor (RF) by maintaining a long period of plateau production. Therefore, a multi-objective approach is presented which incorporates both NPV and RF as objective functions in well placement and rate optimization of Brugge field. The technique of Particle Swarm Optimization (PSO) was used to solve the optimization problem. The search for optimum well locations was conducted in three stages. In the first stage, only NPV was used as the objective function while in the second stage it was only RF. In the third stage, objective function was a weighted sum of NPV and RF in which a set of three weights was used to describe the relative importance of NPV and RF. A comparison of how these weights affect the optimized NPV and RF values is presented. The approach quantitatively clearly differentiates between the operating strategies of NoCs and IoCs and shows how to balance between maximizing profitability and keeping RF as stable as possible. The method takes care for both IoCs and NoCs to optimize the financial aspect (NPV) and the energy sustainability aspect (RF) of field development projects. This technique presents a realistic NPV estimation while keeping a balance in RF for both companies.